Specifications Carbon monoxide <150 ppm
Design Basis Hydrogen sulfide < 10 mg/m3
Sulfur oxides < 800 ppm Specifications
RVP @ 37.8℃ <10 psia (summer)
<12 psia (winter) Specification of Condensate
quality Free water content < 500 ppm vol
Gas Processing & Key Specifications for PNG
Specifications
Export Pressure 92.8 barg
Design Basis
Export Temperature 60°C
Specifications Reference Hydrogen Sulfide(H2S) < 5 mg/Sm3
Specification of Natural Gas
quality Mercaptan sulfur(R-SH) < 15 mg/Sm3
Total Sulfur < 30 mg/Sm3 Carbon Dioxide(CO2) < 2 mol%
Total Inert gas (CO2+N2) < 7 mol%
Water Dew point < -10°C Hydrocarbon Dew point <-7°C
Higher Heating Value 35.59-43.96 MJ/Sm3 Wobbe Index 46.05-52.34 MJ/Sm3 Sales
Gas (PNG)
Gas Export
Cond.
Conde-nsates
Enviro-nmental
Overall gas processing process
PNG Export Flue gas
Sulfur
43
Reception Unit 100
AGRU Unit 101
Dehydration Unit 104
Dewpointing Unit 105
Compression Unit 105 Sulfur
recovery
Acid gas
Condensate Stabilization
Unit 103
Water treatment Condensate
Storage
Spec off gas
Condensate
Heavy HC
FEED
Simulation and Key Operating Conditions
*Aspen HYSYS v8.8 is used for the simulation
Slug catcher Pressure 77.5 barg
Temperature 40 °C
Separator Pressure 75 barg
Temperature 25 °C
AGRU -Absorber
No. of Eq. Stage 30
Pressure 72.5 barg
Temperature 27-56 °C
AGRU -Stripper
No. of Eq. Stage 24
Pressure 1.4-1.6
Temperature 93-131 °C
Dehydration -Absorber
No. of Eq. Stage 8
Pressure 70 barg
Temperature 25°C
Dehydration -Stripper
No. of Eq. Stage 5
Pressure 0-0.1 barg
Temperature 100-131°C
Dew pointing Expansion Pres. 50 barg
Export comp. Pressure 92.8 barg
Temperature 60°C
Condensate stabilizer
No. of Eq. Stage 30
Pressure 9.4-9.7 barg
Temperature 62-200°C
Simulation Results
Required Spec.
Simulation Result
Spec Check Hydrogen Sulfide(H2S) < 5 mg/Sm3 4.92-4.99 Satisfied Total Sulfur < 30 mg/Sm3 12.3-12.5 Satisfied Carbon Dioxide(CO2) < 2 mol% 0.49-0.50 Satisfied Total Inert gas (CO2+N2) < 7 mol% 3.3% Satisfied
Water Dew point < -10°C -10.1 Satisfied
Hydrocarbon Dew point <-7°C -19.7 to -22.8 Satisfied Higher Heating Value 35.59-43.96 MJ/Sm3 38.25 Satisfied Wobbe Index 46.05-52.34 MJ/Sm3 39.35 Satisfied
Export Pressure 92.8 barg 92.8 Satisfied
Export Temperature 60°C 60 Satisfied
Condensate RVP @ 37.8℃ <10/12 psia 8.4-8.6 psia Satisfied
H2S in flue gas 10 mg/m3 trivial Satisfied
Sulfur oxide in flue gas <800 ppm 727 ppm Satisfied
Specifications Check 45
Gas field developments economics
46
CAPEX USD
Gas processing (Offshore) 426,320,000 Jacket 81,752,000 Offshore Pipeline 114,980,000 MEG 21,419,000 Gas processing (Onshore) 235,741,000 Onshore pipeline 50,506,000 Infrastructure 140,076,000 Total 1,070,794,000
Gas processing (Offshore)
40%
Jacket 7%
Offhosre Pipeline
11%
MEG 2%
Gas processing (Onshore)
22%
Onshore pipeline
5%
Infrastructure 13%
Gas processing (Offshore) Jacket
Offhosre Pipeline MEG
Gas processing (Onshore) Onshore pipeline
Separation Acid gas removal Dehydration Dewpoint control
& Stabilization
Gas compression
PFD
Units
Slug catcher: 77.5 bar Separator: 75 bar Flow: 310000 kg/hr
Pressure: 72.5 bar Amine regen. 131oC Flow: 440000 kg/hr
Pressure: 69.5 bar TEG regen. 131 oC Flow: 400000 kg/hr
Pressure: 50 bar Stabilization. 200 oC Flow: 400000 kg/hr
Pressure: 50 → 100 bar Temp.50 → 93 oC Flow 360000 kg/hr
CAPEX
(USD) 513,000 259,000 1,148,000 2,216,000 60,344,000
Gas processing cost breakdown
Operating Conditions – Separation Pressure
▪ To decide operating conditions, sensitivity analysis was performed, based on potential gross profit.
▪ Potential gross profit is estimated as follows:
Potential gross profit = Revenue* – OPEX** – Annualized CAPEX***
▪ 77.5 and 75 barg is recommended as the operating pressure of slug catcher and separation
1) Gas price reference: Index mundi, Nature gas monthly price, Iran Feb, 2018.
https://www.indexmundi.com/commodities/?commodity=natural-gas
2) Condensate price reference: Iran Light, Deliveries to Northwest Europe. https://oilprice.com/oil-price-charts#prices
*Revenue was estimated by using gas (2.67USD/MMBtu)1and condensate (67.47 USD/bbl) price2.
▪ Higher P in separator makes higher CAPEX and results in decreased potential gross profit, although it has higher potential revenue due to more recovered condensates.
▪ However, when the separation pressure is lower than 75, the increased heavy HC contents in gas stream requires lower operating P in dewpointing to satisfy the HC dew point specs. It causes increased CAPEX/OPEX for export compression, which decreases the potential gross profit.
Heater
Cooler
* Minimum pressure drop between SL/separator was assumed as 2.5 bar.
75 barg 77.5 barg
Slug catcher operating pressure (barg)
Separator operating pressure (barg)
Operating Conditions – Separation Temperature
Heater
▪ Low operating temperature in Separator is recommended.
▪ Lower temperature help to recover more condensate, increasing potential gross profit.
▪ When the inlet temperature is too high, cooling before separation may help increase gross profit. CAPEX increase is relatively small.
▪ However, too low temperature may cause hydrate formation problem. In winter season, therefore, heating may be required to prevent hydrate formation.
: At least 15ºC is recommended considering safety margin.
25ºC (normal) 40ºC (normal)
10ºC
(in winter, worst case) 15ºC (in winter)
Cooler
Operating Conditions – AGRU Pressure
▪ DEA amine absorption process is used.
▪ DEA is well-known and one of most commonly used amine for AGRU in gas industries. Although it has slightly higher energy consumption than MDEA, it is still preferable option as a reference process conservatively, due to its long trustable history and wide track records.
▪ 72.5 barg is recommended for AGRU operating pressure*.
▪ When the AGRU operating pressure becomes lower, the operating pressure in dewpointing also becomes lower to satisfy the HC dewpoint spec. It causes increased CAPEX and OPEX in export compression, decreasing gross profit.
* Minimum pressure drop between modules was assumed as 2.5 bar.
72.5 barg
Operating Conditions –Dehydration Pressure
▪ TEG dehydration process is used.
▪ TEG dehydration is a widely used dehydration process for PNG because it has a appreciably lower cost of installation and operation than adsorption (molecular sieve), although generally it will not reduce the water content as low as the adsorption*.
▪ 70 barg is recommended for dehydration operating pressure**.
▪ When the dehydration operating pressure becomes lower, the operating pressure in dewpointing also becomes lower to satisfy the HC dewpoint spec. It causes increased CAPEX and OPEX in export compression, decreasing gross profit.
70 barg
Operating Conditions – Dewpointing
▪ JT expansion process is used.
▪ JT expansion uses the Joule-Thompson effect (temperature drop through a orifice). It does not require additional refrigerant, so is cheap and effective.
▪ Expansion to 50 barg is recommended for dewpointing operating pressure.
▪ When dewpointing pressure decreases, CAPEX and OPEX in export compression increases, resulting reduced potential gross profit.
▪ To satisfy the dewpoint specification, at least 20 bar of pressure drop is required. If the dewpointing pressure is higher than 50 barg, the produced gas cannot satisfy the dewpoint spec.
50 barg 70 barg
Joule-Thomson cooling for LNG production
• The Joule-Thomson (JT) coefficient is the change in temperature that results when a gas is expanded adiabatically from one constant pressure to another without doing external work.
• Thermodynamic definition:
μ = (𝜕𝑇
𝜕𝑃)h = -1
𝐶𝑝(𝜕𝐻
𝜕𝑃)𝑇
• For a real gas, the JT coefficient may be positive (the gas cools upon expansion), negative (the gas warms upon expansion), or zero.
• Upon expansion from 101 bar to 1 bar, the cooling effect upon expansion when started at ambient temperature (27oC) is relatively small. But the cooling effect increases significantly as the initial temperature is lowered.
Temp (K) Pressure (kPa) JT coefficient (K/MPa)
250 500 6.161
250 1000 6.139
250 3000 6.013
250 5000 5.71
250 7500 5.047
250 10000 4.048
250 15000 2.043
250 17500 1.47
250 20000 1.062
250 25000 0.545
250 30000 0.244
Initial Temp (oC) Final Temp (oC) ΔT
27 -20 -47
-23 -87 -64
-43 -137 -94
For methane gas,
For nitrogen gas,
Initial Temp (oC) Final Temp (oC) ΔT
27 8 -19
-23 -51 -28
-43 -77 -34
Example: Simple JT liquefaction cycle
1) Methane is compressed and sent through the heat exchanger and expansion valve.
2) Upon expansion, the gas cools 47oC if the expansion is from 101 to 1 bar, but none liquefies because a
temperature is not reached – 161 oC.
3) All of the chilled low-pressure gas is recycled through the heat exchanger for recompression.
4) This low pressure cold gas lowers the temperature of high pressure gas stream ahead of the expansion valve.
5) Temperature will be progressively lower upon expansion.
The process continues until liquid is formed during the expansion from high to low pressure.
6) The liquid formed is separated from the low pressure gas stream in the liquid receiver. The amount of low pressure gas recycled to the compressor is now reduced, which cuts back on the cooling effect in the heat exchanger.
7) With the addition of makeup gas to the low pressure side of the compressor, a steady-state is reached in the
liquefaction system.
• 1st law of thermodynamics for a steady-state flow system 0 = −Δ ℎ + 𝐾𝐸 + 𝑃𝐸 𝑚 + 𝑚𝑞 − 𝑚𝑤𝑠
• For the thermodynamic boundary, Δℎ = 𝑞𝐿
where the overall enthalpy change of the gas equals the heat leak per unit mass of the gas.
• On a per unit of mass flow of entering gas, f=m2 / m1, the fraction of entering gas withdrawn as a liquid, the equation becomes:
𝑓ℎ2+ 1 − 𝑓 ℎ3− ℎ1 = 𝑞𝐿 or
𝑓 = ℎ3− ℎ1 − 𝑞𝐿 ℎ3− ℎ2
• For a given system, h2, h3, and qL are essentially fixed, so the only way to increase liquefaction is to decrease the inlet gas enthalpy, h1, which is done by increasing the inlet pressure.
Thus more compressor work lead to more liquid production.
• If methane enters the heat exchanger at 27oC and 101 bar, then expand to 1 bar, The fraction of methane that is liquefied can be calculated as follows,
: Ideal heat exchanger – no pressure drop.
: From the pressure-enthalpy diagram and saturation table, At 27 oC and 101 bar, ℎ1 = 350 Btu/lb
At 27 oC and 1 bar, ℎ3 = 392 Btu/lb
For liquid methane at – 161 oC and 1 bar, ℎ2 = 0 Btu/lb : Then the fraction is
𝑓 = ℎ3 − ℎ1 − 𝑞𝐿
ℎ3− ℎ2 = 392 − 350 − 0
392 − 0 = 0.107
→ About 10% of the inlet methane stream is converted to liquefied methane.
: The fraction become maximum when h1 is minimum because the h3 is fixed and qL is independent of pressure. The mathematical criterion is (𝜕ℎ1ൗ𝜕𝑃) = 0.
: From the definition, μ = (𝜕𝑇
𝜕𝑃)h = -1
𝐶𝑝(𝜕𝐻
𝜕𝑃)𝑇, optimum pressure will occur when μ
= 0. However, many other factors must be considered in selecting the economically optimum inlet conditions.
Storage of LNG
Overall heat transfer coefficient, U
• The heat flow through Flat Panels is described using the overall heat transfer coefficient, U in W/m2 oC
𝑈 = 𝑄
𝐴 (𝑇𝑒𝑛𝑣 − 𝑇𝐿𝑁𝐺)
Where Q is the overall heat flow received by the tank, A is the heat transfer area of the membrane in contact with LNG, Tenv is the average temperature of the environment.
• Considering the heat convection and conduction around the panels,
𝑈 = 1
1
ℎ𝐿𝑁𝐺 + 𝑡
λ+ 1 ℎ𝑒𝑛𝑣
Where hLNG and henv are the convective heat transfer coefficient (W/m2 oC) for LNG and environment, respectively, t is the thickness of the panel, and λ is the thermal conductivity of the panel (W/m oC)
• Once we determine the U value, thickness of the insulation layer can be
calculated. For example, U value for LNG carrier was estimated 0.07 W/m2 oC for 160 mm of R-PUF (Reinforced Polyurethane Foam) (λ=0.04 W/moC).